Methods and Compositions for Sand Control in Injection Wells

ABSTRACT

Methods including the steps of providing an injection well having unconsolidated particulates in one or more formation intervals along the wellbore that accept injection fluid; providing a consolidating treatment fluid comprising a base fluid and a consolidating agent; introducing the consolidating treatment fluid through the injection well, while the well is under injection, such that the consolidating treatment fluid enters into a portion of a formation interval along the wellbore that accepts injection fluid; and, allowing the consolidating fluid to consolidate formation particulates therein. The methods may be performed such that the percentage of consolidating agent varies over the course of the treatment or the rate of injection varies over the course of the treatment.

CROSS-REFERENCE TO RELATED CASES

This application is a continuation-in-part application of U.S. patentapplication Ser. No. 12/730,450, entitled “Methods and Compositions forSand Control in Injection Wells,” filed on Mar. 24, 2010, the entiredisclosure of which is incorporated herein by reference.

BACKGROUND

The present invention relates to fluids useful for treating injectionwells to prevent or to reduce migration of particulates therein.

Generally, in the recovery of hydrocarbons, such as oil, from asubterranean formation, the energy required to force the hydrocarbonsinto producing wells may be supplied by the natural pressure driveexisting in the formation or by mechanically lifting hydrocarbons fromthe subterranean formation is through the wells bores of producing wellsto the surface using pumps. However, at the end of primary recoveryoperations, the natural driving pressure may be below a pressuresufficient for production while still leaving a substantial quantity ofhydrocarbons in the subterranean formation. In such cases, secondaryrecovery methods, such as injection operations, may be used to retrievethe remaining hydrocarbons. For example, in typical injection operationsthe energy for producing the remaining hydrocarbons from thesubterranean formation may be supplied by the injection of fluids intothe formation under pressure through one or more injection wellspenetrating the reservoir. The injection fluids then drive thehydrocarbons toward one or more producing wells that are in thereservoir. Typical injection fluids include water, steam, carbondioxide, and natural gas.

The sweep efficiency of injection operations, however, may vary greatlydepending on a number of factors, such as variability in thepermeability of the formation. As used herein the term “sweepefficiency” refers to the measure of the effectiveness of an injectionoperation wherein the operation depends on the volume of the reservoircontacted by the injected fluid. That is, sweep efficiency measures thepercentage of the hydrocarbons displaced from the reservoir by theinjection fluid. In particular, where the subterranean formationcontains high permeability zones, the injection fluids may flow throughthe areas of least resistance, e.g., through the high permeabilityzones, thereby bypassing less permeable zones. While injectionoperations may provide the energy necessary to produce hydrocarbons fromthe high permeability zones, hydrocarbons contained within lesspermeable zones may not be driven to the one or more production wellspenetrating the formation.

However, injection wells experience problems of varying degrees ofseverity when formation solids migrate or are weakened due to theinjection process. These problems are more likely and may be more acutein injection wells that penetrate weak or unconsolidated formations,and/or injection wells that are subject to frequent shut down and startup cycles.

For example, the injection of fluids into a reservoir tends to weakenthe near well bore region surrounding the injection well. The injectionfluids may reduce the cohesive strength of the rock surrounding the wellbore. This effect may be especially severe when the injection fluid isintroduced to the injection well at pressures that exceed the fracturepressure of the formation around the injection well bore. This weakeningmay be particularly severe when a formation is subjected to rapid shutdown cycles, such cycles may cause a water hammer effect that createslocalized stresses and leads to reduced consolidation. Injection wellsthat receive a particularly large amount of injection fluid, for exampleover 30,000 barrels of injection fluid per day are particularlysusceptible to loss of consolidation of formation particulates.

In addition, non-uniform injection rates can cause differential pressureto build between reservoir layers. This differential pressure becomesparticularly problematic if the well is ever shut in for any reason.Upon shut in, the pressure between the layers attempts to equalize,which causes cross-flow between the layers and may result in the influxof formation particulates into the well bore (causing unwanted solidsproduction to shut off the injection flow paths) or into theinterstitial spaces within the formation (decreasing permeability). Thiseffect may be particularly pronounced in areas of the formation thathave already been weakened by the injection fluid.

Another possible failure mechanism for an injection well is that rapidshut down cycles for an injection well can result in water hammereffects that create high localized stress in the immediate well boreregion. These local stresses can result in mechanical failure andproduction of formation solids. Further, in weak formations, injectingwater into the formation can desegregate the rock in the near well boreregion and increase the pressure around the well bore, weakeninggrain-to-grain bonds, and, in some cases forming a completelyunconsolidated mass.

While conventional cased and perforated wells have been used for waterinjection wells, they have been highly prone to failure. Screen only,including expandable screen, completions open hole gravel pack, casedhole gravel pack and frac and pack completions have been used withvarying degrees of success, but failure rates are unacceptable.

Moreover, in some cases there have been channeling problems wherebyfluid from the injection wells follows either high permeability sectionsor channels along bedding plains to the production wells. In thesecases, even a small amount of sand produced at the injection well or theproduction well can result in a fully connected channel forming betweenthe injection well and the production well. This creates an undesirablesituation wherein the injected fluid, rather than propellinghydrocarbons for production, is simply produced out of the producingwell. Stabilization of the formation particles in these highpermeability sections will help stop the movement and erosion of sandinto the production well and help minimize the creation of these highcapacity channels.

SUMMARY

The present invention relates to fluids useful for treating injectionwells to prevent or to reduce migration of particulates therein.

Some embodiments of the present invention provide methods comprising:providing an injection well, the injection well having unconsolidatedparticulates in one or more formation intervals along the wellbore thataccept injection fluid; providing a consolidating treatment fluidcomprising a base fluid and a consolidating agent; introducing aconsolidating treatment fluid through the injection well, while the wellis under injection, such that the consolidating treatment fluid entersinto a portion of a formation interval along the wellbore that acceptsinjection fluid; and, allowing the consolidating fluid to consolidateformation particulates therein.

Other embodiments of the present invention provide methods comprising:providing an injection well; providing a consolidating treatment fluidcomprising a base fluid and a consolidating agent; introducing theconsolidating treatment fluid through the injection well and into aportion of a subterranean formation surrounding the injection well at afirst flow rate; then, introducing the consolidating treatment fluidthrough the injection well and into a portion of a subterraneanformation surrounding the injection well at a second flow rate; then,introducing the consolidating treatment fluid through the injection welland into a portion of a subterranean formation surrounding the injectionwell at a third flow rate; wherein the volume percent of consolidatingagent in the consolidating treatment fluid may vary between the firstflow rate, the second flow rate, and the third flow rate; and, whereinthe first flow rate, second flow rate, and third flow rate are eachdifferent.

Still other embodiments provide methods comprising: providing aninjection well; introducing a first consolidating treatment fluidthrough the injection well and into a portion of a subterraneanformation surrounding the injection well wherein the first consolidatingtreatment fluid comprises a base fluid and a first volume percent ofconsolidating agent; then, introducing a second consolidating treatmentfluid through the injection well and into a portion of a subterraneanformation surrounding the injection well wherein the secondconsolidating treatment fluid comprises a base fluid and a second volumepercent of consolidating agent; then, introducing a third consolidatingtreatment fluid through the injection well and into a portion of asubterranean formation surrounding the injection well wherein the thirdconsolidating treatment fluid comprises a base fluid and a third volumepercent of consolidating agent; wherein the first volume percent ofconsolidating agent, second volume percent of consolidating agent, andthird volume percent of consolidating agent are each different.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention relates to fluids useful for treating injectionwells to prevent or to reduce migration of particulates therein.

As used herein, an “injection well” is a well bore into which fluids areinjected rather than produced. Injection wells are generally designed toaccept an injection fluid to either promote production of hydrocarbonsfrom a production well that is in fluid connection with the injectionwell or to maintain reservoir pressure. As used herein “tackifyingagent” refers to a non-hardening substance that has a nature such thatit is (or may be activated to become) somewhat sticky to the touch. Assuch, the term “tackifying agent” includes, but is not limited to,aggregating agents, agglomerating agents and surface modificationagents. These include compositions that are used in changing ormodifying the aggregation potential and/or zeta potential of theparticulates or substrate surfaces even though such zeta potentialmodifications may not result in a “tacky” substance. The term“tackifying agent” is not meant to encompass resin material that curesto form a hard substance. As used herein, the term “consolidating agent”refers to a tackifying agent, a resin, or a combination thereof. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted for the purposes ofunderstanding this invention.

In some embodiments, the methods of the present invention may reduce thelikelihood of, or decrease the severity of, loss of consolidation in thereservoir penetrated by an injection well. In some embodiments, themethods of the present invention reduce the likelihood that formationsolids from the injection well will be produced. For example,introducing consolidating treatment fluid (comprising a tackifyingagent, a resin, or some combination thereof), to an injection well inaccordance with the methods of the present invention may prevent theproduction of formation solids caused by cross-flow in the injectionwell bore when it is shut-in, so that formation solids do not enter theinjection well bore.

Some embodiments of the present invention comprise providing aninjection well and introducing a consolidating treatment fluid to theinjection well, wherein the tackifying treatment fluid comprises a basefluid and a tackifying agent, a resin, or a combination thereof.Suitable tackifying agents include (1) aqueous tackifying agents, (2)non-aqueous tackifying agents, (3) gelable compositions, and (4) zetapotential altering systems. In some embodiments the consolidating agentmay comprise a mixture of more than one type of tackifying agent. Insome embodiments, the consolidating treatment fluid is a dilutedispersion, micro-emulsion, or micro-dispersion of the chosen agent inan aqueous base fluid. The consolidating treatment fluid may beintroduced into the injection well at any desired rate. For example, insome circumstances it may be desirable to place the fluid at or belowmatrix flow rates (that is, at or below the rate at which the pressuresexerted on the formation would surpass the fracture pressure) and inother circumstances, it may be desirable to place the fluid above matrixrate (that is, at a rate at which the pressure is sufficient to createor enhance fracture or channels within the formation).

In some embodiments, small droplets or particles of consolidating agentmay be deposited on formation surfaces in the formation matrix and canprovide a cohesive coating that helps to stabilize the formationinhibiting the movement of formation particles and sand grains andpreventing fines movement. In situations where the consolidating agentis placed above matrix rates, droplets or particles of consolidatingagent may form a coating on the formation particulates at the faces ofthe fractures even as the fractures are being formed. Suitabletackifying agents bind the formation particulates together into a loosenetwork and discourage particle movement and migration of fines. In somepreferred embodiments, it may be desirable to place a tackifying agentwhen it is in a relatively non-tacky state, and then to contact theagent with an activator that increases the tacky nature of thesubstance—such embodiments may allow for placement of the tackifyingagent at desired locations within the formation before adherence. Inother embodiments, the tackifying agents do not require an activator andmay be added directly to the injection fluid at any time to provideformation stabilization. Similarly, in some embodiments it may bedesirable to place a two-component resin system such that the firstcomponent can be placed and then later caused to cure (harden) when thesecond component is placed.

According to some embodiments, the consolidating agent may be introducedto the injection well continuously, intermittently, or at only certainpoints in the treatment process. For example, the consolidatingtreatment fluid may form part of a continuous injection fluid streamduring an injection operation; this embodiment may be particularlydesirable in circumstances where the injection operation is performed ator above fracture rates. In other embodiments, the consolidating agentmay be added to an existing injection fluid stream in intermittentstages. In any event, the consolidating agent may generally be added tothe injection stream without disrupting operations at the injectionwell. In embodiments wherein the consolidating agent is placed at ratesabove the fracturing pressure of the injection well, droplets and/orparticles of consolidating agent may be transported into the fractureuntil they are leaked off through the fracture face where they can coatthe formation particles to provide stabilization, to inhibit solidsmovement, and to reduce fines movement. Similarly, in some embodiments,the consolidating agent may leak off into and at least partially coatfractures or channels in the formation, including those formed while theconsolidating agent is being introduced into the formation.

In some embodiments, the amount of consolidating agent introduced intothe injection well will depend on the amount of injection fluid to beinjected. A variety of completion techniques may be used, includingstepped rate treatments, constant rate treatments, and long termmaintenance treatments, among others. That is, the concentration of theconsolidating treatment fluid that flows with the injection fluid maychange over the course of the treatment, within a single stage of addingconsolidating treatment fluid, or across multiple stages of addingconsolidating treatment fluid. In some embodiments, the consolidatingagent may be introduced to the injection well in an amount ranging froma lower limit of about 0.01%, 0.02%, 0.05%, 0.1%, 0.5%, 1.0%, 1.5%, 2%,2.5%, 3%, 4%, 5%, or 6% by volume of the injection fluid, to an upperlimit of about 20%, 15%, 10%, 9%, 8%, 7%, 6%, 5% 4.5%, 4%, 3.5%, 3%, 2%,2.5%, or 1% by volume of the injection fluid, and wherein the percentageof consolidating agent may range from any lower limit to any upper limitto the extent that the selected range encompass an subset between theupper and lower limits. Some of the lower limits listed above aregreater than some of the listed upper limits, one skilled in the artwill recognize that the selected subset will require the selection of anupper limit in excess of the selected lower limit.

In addition, in some circumstances, the consolidating agent may beplaced only over a small percentage of an injection operation—such as a10 minute period injecting a consolidating agent at 0.5% by volume ofthe injection fluid and then no additional consolidating agent during aweek of injection before again injecting a consolidating agent at 0.5%by volume of the injection fluid for 10 minutes. One skilled in the artwill recognize that a higher concentration of consolidating agent mightbe better suited shorter term, slug-type treatments whereas a lowerconcentration of consolidating agent might be better suited for longerterm injections. In addition, one skilled in the art will recognize thatusing a higher concentration of consolidating agent in a slug-typetreatment might be well-suited for methods wherein it is desirable tomitigate cross-flow when the method is employed shortly before aninjection operation is stopped.

In stepped rate treatments of the present invention, initial injectionis performed at a matrix rate (that is, a flow rate/pressure below thefracture flow rate/pressure of the treated portion of the formation) andthen the rate is gradually increased until the desired rate is achieved.The desired rate may be at or above a fracturing rate, but in someembodiments the entire treatment may be performed at matrix rates.During such stepped rate treatments, a consolidating agent is preferablyincluded at each stage of the treatment to ensure that the treatedportion of the subterranean formation is adequately consolidated. It ismost preferred that, at least, each portion of the treatment performedat a matrix flow rate includes consolidating agent in the injectedfluid.

In constant rate treatments of the present invention, a desiredinjection rate is quickly established (rather than gradually establishedas in the stepped rate treatments discussed above) and then the desiredrate is held as constant as possible throughout the injection treatment.In some constant rate treatments, a constant amount of consolidatingagent is continuously added to the injected fluids, perhaps atrelatively low volume of consolidating agent. In other constant rateembodiments, the consolidating agent is added to the constant rateinjection fluid in one or more slugs of treatment; in such embodimentsit may be desirable to use relatively higher amounts of consolidatingagent.

“Long term maintenance treatments,” as that term is used herein, refersto the use of consolidating agents over the life, or a portion of thelife of an injection well in operation. In such operations, it may bedesirable to periodically inject consolidating agents into the well tominimize long term degradation of previously placed treatments, and tominimize the migration of particulates over the life of the well.

In other embodiments, it may be desirable to taper the concentration ofconsolidating agent such that it is first introduced to the injectionwell in a higher concentration, and the concentration is continuouslyreduced. Alternatively, the consolidating treatment fluid may beintroduced to the injection well intermittently, and each time it isintroduced, the concentration of consolidating agent is successivelyreduced. By way of example, it might be desirable to begin a treatmentat about 0.5% consolidating agent by volume of the injection fluid forless than about an hour and then have that concentration decrease toabout 0.05% for a longer-term application. Tapering the concentration ofthe consolidating agent during the course of treatment may allow theconsolidating agent to penetrate further from the well bore to enhancethe formation strength along fractures and prevent fines movement alongthe fracture during shut-in cycles. In one example embodiment, over thecourse of a one-hour stage of adding consolidating treatment fluid, theconcentration of consolidating agent flowing with the injection fluidmay decrease from an initial concentration of about 5% by volumeconsolidating agent to about 0.5% by volume by the end of the treatmenthour. In another example embodiment, the concentration of consolidatingtreatment fluid flowing with the injection fluid may decrease from aninitial concentration of about 1% by volume consolidating agent to about0.01% by volume over the course of a continuous injection period lastingseveral days. The selection of the amount of consolidating agent to beused depends on many factors, including the selected agent, the level ofconsolidation in the portion of the reservoir being treated, and therate of placement.

In some embodiments, cycling between stages of adding consolidatingtreatment fluid with the injection fluid and allowing the injectionfluid to flow without consolidating treatment fluid, or continuouslyadding the consolidating treatment fluid for a longer period of time maybe beneficial because as new formation rock is exposed over time, itbecomes at least partially coated and stabilized with the tackifyingagent. For example, when the consolidating treatment fluid is flowingwith the injection fluid, the well bore is stabilized during theinjection process. If the consolidating treatment fluid flows with theinjection fluid at a pressure sufficient to create or enhance a fracturein the formation or at other high rates of injection, the consolidatingtreatment fluid will continuously reduce or prevent erosion caused bythe high rate of injection. Similarly, if the preferred fracturingdirection is changed over time and fractures are created in newdirections through previously un-fractured rock, the newly fracturedrock may become at least partially coated with consolidating agent.

Suitable base fluids that may be used in the consolidating injectionfluid of the present invention may be aqueous or nonaqueous. Suitableaqueous base fluids include fresh water, salt water, brine, seawater, orany other fluid that, preferably, does not adversely react with theother components used in accordance with this invention or with thesubterranean formation. Suitable nonaqueous base fluids include diesel,kerosene, short chain alcohols (methyl alcohol, ethyl alcohol, propylalcohol, isopropyl alcohol, butyl alcohol), glycerol, ethers or anyother fluid that, preferably, does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation. One should note, however, that if long-termstability of the emulsion or dispersion of the consolidating treatmentfluid is desired, in some embodiments, the preferred aqueous base fluidmay be one that is substantially free of salts. It is within the abilityof one skilled in the art with the benefit of this disclosure todetermine if and how much salt may be tolerated in the consolidatingtreatment fluids of the present invention before it becomes problematicfor the stability of the emulsion or dispersion. In embodiments in whichthe consolidating treatment fluid is an emulsion, the aqueous fluid maybe present in an amount in the range of about 20% to about 99.9% byweight of the consolidating treatment fluid, alternatively, in an amountin the range of about 60% to about 99.9% by weight of the consolidatingtreatment fluid, or alternatively in an amount in the range of about 95%to about 99.9% by weight of the consolidating treatment fluid.

In embodiments in which the consolidating treatment fluid is anemulsion, the aqueous fluid may be present in an amount ranging from alower limit of about 20% by weight of the consolidating treatment fluid,60%, 75%, 85%, or 95%, to an upper limit of about 99.9% by weight of theconsolidating treatment fluid, 99%, 98%, 97%, or 96%, and wherein thepercentage of particulates may range from any lower limit to any upperlimit and encompass a subset between the upper and lower limits. Otherranges may be suitable as well, depending on the other components of theconsolidating treatment fluid.

Suitable tackifying agents include aqueous agglomerating or tackifyingagents, non-aqueous agglomerating or tackifying agents, gelablecompositions, and zeta potential altering systems, as described below:

Aqueous Tackifying Agents.

Aqueous tackifying compositions suitable for use in the presentinvention generally are charged polymers that comprise compounds that,when in an aqueous solvent or solution, will form a tacky, non-hardeningcoating (by themselves or with an activator) and, when placed on aparticulate, will increase the continuous critical resuspension velocityof the particulate when contacted by a stream of water. The term“continuous critical resuspension velocity” as used herein essentiallyrefers to the velocity of horizontal flowing water that is high enoughto continuously pick up particles from an alcove or pipe-T belowhorizontal flowing water. U.S. Pat. No. 5,787,986, the entire disclosureof which is hereby incorporated by reference, contains additionalinformation defining this term at, inter alia, Example 1 and FIG. 1.

The aqueous tackifying agent may enhance the grain-to-grain contactbetween the individual particulates within the formation (be theyproppant particulates, formation fines, or other particulates), helpingbring about the agglomeration or consolidation of the particulates intoa stabilized mass. Examples of aqueous tackifying agents suitable foruse in the present invention include, but are not limited to, acrylicacid polymers, acrylic acid ester polymers, acrylic acid derivativepolymers, acrylic acid homopolymers, acrylic acid ester homopolymers(such as poly(methyl acrylate), poly (butyl acrylate), andpoly(2-ethylhexyl acrylate)), acrylic acid ester co-polymers,methacrylic acid derivative polymers, methacrylic acid homopolymers,methacrylic acid ester homopolymers (such as poly(methyl methacrylate),poly(butyl methacrylate), and poly(2-ethylhexyl methacrylate)),acrylamido-methyl-propane sulfonate polymers, acrylamido-methyl-propanesulfonate derivative polymers, acrylamido-methyl-propane sulfonateco-polymers, and acrylic acid/acrylamido-methyl-propane sulfonateco-polymers, and combinations thereof. Methods of determining suitableaqueous tackifying compositions and additional disclosure on aqueoustackifying compositions can be found in U.S. Patent ApplicationPublication No. 2005/0277554, filed Jun. 9, 2004, and U.S. Pat. No.7,131,491 issued Nov. 7, 2006, the relevant disclosures of which arehereby incorporated by reference. Others that may be suitable includethose described in U.S. Pat. No. 5,249,627, the relevant disclosure ofwhich is incorporated herein by reference.

Surfactants may be used along with the aqueous tackifying agents in themethods of the present invention. The choice of whether to use asurfactant will be governed at least in part by the mineralogy of theformation. Generally, a surfactant may help facilitate coating of thefines by the treatment fluid. For instance, a hydrophobic polymer havinga negative charge will preferentially attach to surfaces having apositive to neutral zeta potential and/or a hydrophilic surface.Therefore, in particular embodiments, a cationic surfactant may beincluded in a treatment fluid to facilitate application of the aqueoustackifying agent on the fines. As will be understood by those skilled inthe art, amphoteric and zwitterionic surfactants also may be used solong as the conditions they are exposed to during use are such that theydisplay the desired charge. For example, in particular embodiments,mixtures of cationic and amphoteric surfactants may be used.

In some embodiments, the surfactant may be used in the aqueoustackifying agent in an amount ranging from a lower limit of about 0.01%,0.02%, 0.05%, 0.1%, 0.5%, 1.0%, 2%, 3%, 4%, 5%, or 6% by volume of theaqueous tackifying agent, to an upper limit of about 20%, 15%, 10%, 9%,8%, 7%, 6%, 5% 4.5%, 4%, 3.5%, 3%, 2%, or 1% by volume of the aqueoustackifying agent, and wherein the percentage of surfactant may rangefrom any lower limit to any upper limit to the extent that the selectedrange encompass an subset between the upper and lower limits. Some ofthe lower limits listed above are greater than some of the listed upperlimits, one skilled in the art will recognize that the selected subsetwill require the selection of an upper limit in excess of the selectedlower limit.

Non-Aqueous Tackifying Compositions.

In certain embodiments of the present invention, the consolidating agentcomprises a non-aqueous tackifying composition. As used herein, the term“tackifying composition” refers to a material that exhibits a sticky ortacky character. Non-aqueous tackifying compositions suitable for use inthe present invention comprise substantially any non-aqueous substancethat, when in liquid form or in a solvent solution, will form a coatingupon a particulate. One example of a suitable group of non-aqueoustackifying compositions comprises polyamides which are liquids or insolution at the temperature of the subterranean formation such that thepolyamides are, by themselves, non-hardening when present on theparticulates introduced into the subterranean formation. A particularlypreferred product is a condensation reaction product comprised ofcommercially available polyacids and a polyamine. Such commercialproducts include compounds such as mixtures of C36 dibasic acidscontaining some trimer and higher oligomers and small amounts of monomeracids that are reacted with polyamines. Other polyacids include trimeracids, synthetic acids produced from fatty acids, maleic anhydride andacrylic acid and the like. Such acid compounds are commerciallyavailable from companies such as Witco Corporation, Union Camp,Chemtall, and Emery Industries. The reaction products are availablefrom, for example, Champion Technologies, Inc. and Witco Corporation.Additional compounds that may be used as tackifying compounds includeliquids and solutions of, for example, polyesters, polycarbonates,polycarbamates, natural resins such as shellac and the like. Suitabletackifying compounds are described in U.S. Pat. No. 5,853,048 issued toWeaver, et al. and U.S. Pat. No. 5,833,000 issued to Weaver, et al., thedisclosures of which are herein incorporated by reference.

In some embodiments, it may be desirable to add a solvent to thenon-aqueous tackifying compositions. The solvents that can be used inthe present invention preferably include those having high flash points(most preferably above about 125° F.). Examples of solvents suitable foruse in the present invention include, but are not limited to,butylglycidyl ether, dipropylene glycol methyl ether, butyl bottomalcohol, dipropylene glycol dimethyl ether, diethyleneglycol methylether, ethyleneglycol butyl ether, methanol, butyl alcohol, isopropylalcohol, diethyleneglycol butyl ether, propylene carbonate, d'limonene,2-butoxy ethanol, butyl acetate, furfuryl acetate, butyl lactate,dimethyl sulfoxide, dimethyl formamide, fatty acid methyl esters, andcombinations thereof.

Zeta Potential Altering Systems

Zeta potential as used herein is defined by the charge that develops atthe interface in the boundary of hydrodynamic shear between solidsurfaces as a product of the electrostatic repulsion and the attractiveforces related to the Van der Waals' forces. That is, zeta potential isa function of the surface charge of the particle, any adsorbed layer atthe interface, and the nature and composition of the surroundingsuspension medium. Zeta potential can be affected by changes in pH,conductivity of the medium (salinity and kind of salt), andconcentration of particular additives (polymer, non-ionic surfactants,etc.). Systems useful in the present invention are those that are ableto alter the zeta potential of the surfaces and particulates beingtreated to have zeta potential values between −20 and 20 mV. A zetapotential between −20 and 20 mV corresponds to an effective charge lowenough that the repulsion is lowered to a point where aggregationoccurs.

The active ingredient of suitable zeta potential altering systems is aninner salt of a very low-molecular weight polymer, that when added to atreatment fluid disperses and rapidly coats any metal oxide substrate itencounters, such as proppant or subterranean formation. It also containsa penetrating alcohol, such as methanol, capable of disrupting the waterlayer that coats solid surfaces in the formation. The zeta potentialaltering system does not modify the chemical structure of frictionreducers and gelling systems such as nonionic, cationic, and anionicpolyacrylamide and guar gums and derivatives, making it compatible withslick-water systems and borate-based crosslinked gels. The activecomponent is stable in acid and caustic solutions except under extremeconditions and is thermally stable to 450° F. Examples of suitablezeta-potential altering systems are described in U.S. Patent PublicationNo. 2009/0203553 and U.S. Pat. No. 7,350,579, the entire disclosures ofwhich are hereby incorporated by reference.

Gelable Compositions.

In some embodiments, the tackifying agents comprise a gelablecomposition. Gelable compositions suitable for use in the presentinvention include those compositions that cure to form a semi-solid,immovable, gel-like substance. The gelable composition may be anygelable liquid composition capable of converting into a gelled substancecapable of substantially plugging the permeability of the formationwhile allowing the formation to remain flexible. As referred to in thisdisclosure, the term “flexible” refers to a state wherein the treatedformation is relatively malleable and elastic and able to withstandsubstantial pressure cycling without substantial breakdown of theformation. Thus, the resultant gelled substance stabilizes the treatedportion of the formation while allowing the formation to absorb thestresses created during pressure cycling. As a result, the gelledsubstance may aid in preventing breakdown of the formation both bystabilizing and by adding flexibility to the treated region. Examples ofsuitable gelable liquid compositions include, but are not limited to,(a) gelable resin compositions, (b) gelable aqueous silicatecompositions, (c) crosslinkable aqueous polymer compositions, and (d)polymerizable organic monomer compositions.

Gelable Compositions—Gelable Resins

In some embodiments, the tackifying agents may comprise a gelable resincomposition that cures to form a stiff gel. Suitable gelable resincompositions form flexible, resilient gelled substances. Gelable resincompositions allow the treated portion of the formation to remainflexible and to resist breakdown. Generally, the gelable resincompositions useful in accordance with this invention comprise a curableresin, a diluent, and a resin curing agent. When certain resin curingagents, such as polyamides, are used in the gelable resin compositions,the compositions form the semi-solid, immovable, gelled substancesdescribed above. Where the resin curing agent used may cause the organicresin compositions to form hard, brittle material rather than a desiredgelled substance, the curable resin compositions may further compriseone or more “flexibilizer additives” (described in more detail below) toprovide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present inventioninclude, but are not limited to, organic resins such as polyepoxideresins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins,urea-aldehyde resins, furan resins, urethane resins, and mixturesthereof. Of these, polyepoxide resins are preferred.

Any solvent that is compatible with the gelable resin and achieves thedesired viscosity effect may be suitable for use in the presentinvention. Examples of solvents that may be used in the gelable resincompositions of the present invention include, but are not limited to,phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; etherssuch as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidylether; and mixtures thereof. In some embodiments of the presentinvention, the solvent comprises butyl lactate. Among other things, thesolvent acts to provide flexibility to the cured composition. Thesolvent may be included in the gelable resin composition in an amountsufficient to provide the desired viscosity effect.

Generally, any resin curing agent that may be used to cure an organicresin is suitable for use in the present invention to form a gelableresin. When the resin-curing agent chosen is an amide or a polyamide,generally no flexibilizer additive will be required because such curingagents cause the gelable resin composition to convert into a semi-solid,immovable, gelled substance. Other suitable resin curing agents (such asan amine, a polyamine, methylene dianiline, and other curing agentsknown in the art) will tend to cure into a hard, brittle material andwill thus benefit from the addition of a flexibilizer additive.Generally, the resin curing agent used is included in the gelable resincomposition, whether a flexibilizer additive is included or not, in anamount in the range of from about 5% to about 75% by weight of thecurable resin. In some embodiments of the present invention, theresin-curing agent used is included in the gelable resin composition inan amount in the range of from about 20% to about 75% by weight of thecurable resin.

As noted above, flexibilizer additives may be used to provideflexibility to the gelled substances formed from the curable resincompositions. Flexibilizer additives may be used where the resin-curingagent chosen would cause the gelable resin composition to cure into ahard and brittle material—rather than a desired gelled substance. Forexample, flexibilizer additives may be used where the resin curing agentchosen is not an amide or polyamide. Examples of suitable flexibilizeradditives include, but are not limited to, an organic ester, anoxygenated organic solvent, an aromatic solvent, and combinationsthereof. Of these, ethers, such as dibutyl phthalate, are preferred.Where used, the flexibilizer additive may be included in the gelableresin composition in an amount in the range of from about 5% to about80% by weight of the gelable resin. In some embodiments of the presentinvention, the flexibilizer additive may be included in the curableresin composition in an amount in the range of from about 20% to about45% by weight of the curable resin.

Gelable Compositions—Gelable Aqueous Silicate Compositions

In some embodiments, the tackifying agents of the present invention maycomprise a gelable aqueous silicate composition. Generally, the gelableaqueous silicate compositions that are useful in accordance with thepresent invention generally comprise an aqueous alkali metal silicatesolution and a temperature activated catalyst for gelling the aqueousalkali metal silicate solution.

The aqueous alkali metal silicate solution components of the gelableaqueous silicate compositions generally comprise an aqueous liquid andan alkali metal silicate. The aqueous liquid component of the aqueousalkali metal silicate solution generally may be fresh water, salt water(e.g., water containing one or more salts dissolved therein), brine(e.g., saturated salt water), seawater, or any other aqueous liquid thatdoes not adversely react with the other components used in accordancewith this invention or with the subterranean formation. Examples ofsuitable alkali metal silicates include, but are not limited to, one ormore of sodium silicate, potassium silicate, lithium silicate, rubidiumsilicate, or cesium silicate. Of these, sodium silicate is preferred.While sodium silicate exists in many forms, the sodium silicate used inthe aqueous alkali metal silicate solution preferably has a Na₂O-to-SiO₂weight ratio in the range of from about 1:2 to about 1:4. Mostpreferably, the sodium silicate used has a Na₂O-to-SiO₂ weight ratio inthe range of about 1:3.2. Generally, the alkali metal silicate ispresent in the aqueous alkali metal silicate solution component in anamount in the range of from about 0.1% to about 10% by weight of theaqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueoussilicate compositions is used to convert the gelable aqueous silicatecompositions into the desired semi-solid, immovable, gelled substancedescribed above. Selection of a temperature-activated catalyst isrelated, at least in part, to the temperature of the subterraneanformation to which the gelable aqueous silicate composition will beintroduced. The temperature-activated catalysts that can be used in thegelable aqueous silicate compositions of the present invention include,but are not limited to, ammonium sulfate (which is most suitable in therange of from about 60° F. to about 240° F.); sodium acid pyrophosphate(which is most suitable in the range of from about 60° F. to about 240°F.); citric acid (which is most suitable in the range of from about 60°F. to about 120° F.); and ethyl acetate (which is most suitable in therange of from about 60° F. to about 120° F.). Generally, thetemperature-activated catalyst is present in the gelable aqueoussilicate composition in the range of from about 0.1% to about 5% byweight of the gelable aqueous silicate composition.

Gelable Compositions—Crosslinkable Aaueous Polymer Compositions

In other embodiments, the tackifying agent of the present inventioncomprises a crosslinkable aqueous polymer composition. Generally,suitable crosslinkable aqueous polymer compositions comprise an aqueoussolvent, a crosslinkable polymer, and a crosslinking agent. Suchcompositions are similar to those used to form gelled treatment fluids,such as fracturing fluids; however, according to the methods of thepresent invention, they are not exposed to breakers or de-linkers and sothey retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which thecrosslinkable composition and the crosslinking agent may be dissolved,mixed, suspended, or dispersed therein to facilitate gel formation. Forexample, the aqueous solvent used may be fresh water, salt water, brine,seawater, or any other aqueous liquid that does not adversely react withthe other components used in accordance with this invention or with thesubterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkableaqueous polymer compositions include, but are not limited to,carboxylate-containing polymers and acrylamide-containing polymers.Preferred acrylamide-containing polymers include polyacrylamide,partially hydrolyzed polyacrylamide, copolymers of acrylamide andacrylate, and carboxylate-containing terpolymers and tetrapolymers ofacrylate. Additional examples of suitable crosslinkable polymers includehydratable polymers comprising polysaccharides and derivatives thereofand that contain one or more of the monosaccharide units galactose,mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronicacid, or pyranosyl sulfate. Suitable natural hydratable polymersinclude, but are not limited to, guar gum, locust bean gum, tara,konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, andcarrageenan, and derivatives of all of the above. Suitable hydratablesynthetic polymers and copolymers that may be used in the crosslinkableaqueous polymer compositions include, but are not limited to,polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride,methylvinyl ether polymers, polyvinyl alcohols, andpolyvinylpyrrolidone. The crosslinkable polymer used should be includedin the crosslinkable aqueous polymer composition in an amount sufficientto form the desired gelled substance in the subterranean formation. Insome embodiments of the present invention, the crosslinkable polymer isincluded in the crosslinkable aqueous polymer composition in an amountin the range of from about 1% to about 30% by weight of the aqueoussolvent. In another embodiment of the present invention, thecrosslinkable polymer is included in the crosslinkable aqueous polymercomposition in an amount in the range of from about 1% to about 20% byweight of the aqueous solvent.

The crosslinkable aqueous polymer compositions suitable for use in themethods of the present invention further comprise a crosslinking agentfor crosslinking the crosslinkable polymers to form the desired gelledsubstance. In some embodiments, the crosslinking agent is a molecule orcomplex containing a reactive transition metal cation. A most preferredcrosslinking agent comprises trivalent chromium cations complexed orbonded to anions, atomic oxygen, or water. Examples of suitablecrosslinking agents include, but are not limited to, compounds orcomplexes containing chromic acetate and/or chromic chloride.

Other suitable transition metal cations include chromium VI within aredox system, aluminum III, iron II, iron III, and zirconium IV. Instill other embodiments, a chitosan may be used as a suitablecrosslinking agent as described in U.S. Pat. Nos. 6,258,755, 6,291,404,6,607,035, 6,176,315, 6,764,981, and 6,843,841 the relevant disclosuresof which are hereby incorporated by reference.

The crosslinking agent should be present in the crosslinkable aqueouspolymer compositions in an amount sufficient to provide, inter alia, thedesired degree of crosslinking. In some embodiments of the presentinvention, the crosslinking agent may be present in the crosslinkableaqueous polymer compositions of the present invention in an amount inthe range of from about 0.01% to about 5% by weight of the crosslinkableaqueous polymer composition. The exact type and amount of crosslinkingagent or agents used depends upon the specific crosslinkable polymer tobe crosslinked, formation temperature conditions, and other factorsknown to those individuals skilled in the art.

Optionally, the crosslinkable aqueous polymer compositions may furthercomprise a crosslinking delaying agent, such as a polysaccharidecrosslinking delaying agent derived from guar, guar derivatives, orcellulose derivatives. The crosslinking delaying agent may be includedin the crosslinkable aqueous polymer compositions, inter alia, to delaycrosslinking of the crosslinkable aqueous polymer compositions untildesired. One of ordinary skill in the art, with the benefit of thisdisclosure, will know the appropriate amount of the crosslinkingdelaying agent to include in the crosslinkable aqueous polymercompositions for a desired application.

Gelable Compositions—Polymerizable Organic Monomer Compositions

In other embodiments, the gelled liquid compositions suitable for use inthe methods of the present invention comprise polymerizable organicmonomer compositions. Generally, suitable polymerizable organic monomercompositions comprise an aqueous-base fluid, a water-solublepolymerizable organic monomer, an oxygen scavenger, and a primaryinitiator.

The aqueous-based fluid component of the polymerizable organic monomercomposition generally may be fresh water, salt water, brine, seawater,or any other aqueous liquid that does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation.

A variety of monomers are suitable for use as the water-solublepolymerizable organic monomers in the present invention. Examples ofsuitable monomers include, but are not limited to, acrylic acid,methacrylic acid, acrylamide, methacrylamide,2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide,vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate,2-triethylammoniumethylmethacrylate chloride,N,N-dimethyl-aminopropylmethacryl-amide,methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammoniumsulfate, and mixtures thereof. Preferably, the water-solublepolymerizable organic monomer should be self-crosslinking. Examples ofsuitable monomers which are self-crosslinking include, but are notlimited to, hydroxyethylacrylate, hydroxymethylacrylate,hydroxyethylmethacrylate, N-hydroxymethylacrylamide,N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate,polyethylene glycol methacrylate, polypropylene glycol acrylate,polypropylene glycol methacrylate, and mixtures thereof. Of these,hydroxyethylacrylate is preferred. An example of a particularlypreferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where amixture thereof is used) should be included in the polymerizable organicmonomer composition in an amount sufficient to form the desired gelledsubstance after placement of the polymerizable organic monomercomposition into the subterranean formation. In some embodiments of thepresent invention, the water-soluble polymerizable organic monomer isincluded in the polymerizable organic monomer composition in an amountin the range of from about 1% to about 30% by weight of the aqueous-basefluid. In another embodiment of the present invention, the water-solublepolymerizable organic monomer is included in the polymerizable organicmonomer composition in an amount in the range of from about 1% to about20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer compositionmay inhibit the polymerization process of the water-solublepolymerizable organic monomer or monomers. Therefore, an oxygenscavenger, such as stannous chloride, may be included in thepolymerizable monomer composition. In order to improve the solubility ofstannous chloride so that it may be readily combined with thepolymerizable organic monomer composition on the fly, the stannouschloride may be pre-dissolved in a hydrochloric acid solution. Forexample, the stannous chloride may be dissolved in a 0.1% by weightaqueous hydrochloric acid solution in an amount of about 10% by weightof the resulting solution. The resulting stannous chloride-hydrochloricacid solution may be included in the polymerizable organic monomercomposition in an amount in the range of from about 0.1% to about 10% byweight of the polymerizable organic monomer composition. Generally, thestannous chloride may be included in the polymerizable organic monomercomposition of the present invention in an amount in the range of fromabout 0.005% to about 0.1% by weight of the polymerizable organicmonomer composition.

The primary initiator is used to initiate polymerization of thewater-soluble polymerizable organic monomer(s) used in the presentinvention. Any compound or compounds that form free radicals in aqueoussolution may be used as the primary initiator. The free radicals act,inter alia, to initiate polymerization of the water-solublepolymerizable organic monomer present in the polymerizable organicmonomer composition. Compounds suitable for use as the primary initiatorinclude, but are not limited to, alkali metal persulfates; peroxides;oxidation-reduction systems employing reducing agents, such as sulfitesin combination with oxidizers; and azo polymerization initiators.Preferred azo polymerization initiators include2,2′-azobis(2-imidazole-2-hydroxyethyl)propane,2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), and2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide. Generally, theprimary initiator should be present in the polymerizable organic monomercomposition in an amount sufficient to initiate polymerization of thewater-soluble polymerizable organic monomer(s). In certain embodimentsof the present invention, the primary initiator is present in thepolymerizable organic monomer composition in an amount in the range offrom about 0.1% to about 5% by weight of the water-soluble polymerizableorganic monomer(s). One skilled in the art will recognize that as thepolymerization temperature increases, the required level of activatordecreases.

Optionally, the polymerizable organic monomer compositions further maycomprise a secondary initiator. A secondary initiator may be used, forexample, where the immature aqueous gel is placed into a subterraneanformation that is relatively cool as compared to the surface mixing,such as when placed below the mud line in offshore operations. Thesecondary initiator may be any suitable water-soluble compound orcompounds that may react with the primary initiator to provide freeradicals at a lower temperature. An example of a suitable secondaryinitiator is triethanolamine. In some embodiments of the presentinvention, the secondary initiator is present in the polymerizableorganic monomer composition in an amount in the range of from about 0.1%to about 5% by weight of the water-soluble polymerizable organicmonomer(s).

Also optionally, the polymerizable organic monomer compositions suitablefor use in the methods of the present invention further may comprise acrosslinking agent for crosslinking the polymerizable organic monomercompositions in the desired gelled substance. In some embodiments, thecrosslinking agent is a molecule or complex containing a reactivetransition metal cation. A most preferred crosslinking agent comprisestrivalent chromium cations complexed or bonded to anions, atomic oxygen,or water. Examples of suitable crosslinking agents include, but are notlimited to, compounds or complexes containing chromic acetate and/orchromic chloride. Other suitable transition metal cations includechromium VI within a redox system, aluminum III, iron II, iron III, andzirconium IV.

Resins

In addition to tackifying agents, in some embodiments of the presentinvention, a resin treatment fluid may be introduced to an injectionwell prior to the time that a tackifying treatment fluid is introduced.Placement of a resin before the tackifying agent may help to develophigh strength in the near well bore area before subsequent introductionof an injection fluid at a high rate and pressure. In general, a resintreatment fluid that is used in accordance with the methods of thepresent invention comprises a resin material dispersed in an aqueousbase fluid such as a brine. In cases in which a consolidating treatmentfluid precedes the tackifying treatment fluid, the resin material ispreferably allowed to at least partially cure in the formation beforethe tackifying treatment fluid is introduced. Curing of theconsolidating material in at least a portion of the formationsurrounding the injection well may consolidate and stabilize that areainto a permeable, consolidated mass. In exemplary embodiments, the resinis present in the resin treatment fluid in a low concentration so as tominimize formation damage while still providing relatively high strengthto the formation when cured. One skilled in the art will recognize thathigher concentrations of resin may be used to provide additionalstrength to the formation; however, subsequent regained permeability ofthe formation may be sacrificed. Similarly, one skilled it the art willrecognize that the strength conferred by the consolidating treatmentfluid may depend on how far the consolidating treatment fluid isover-displaced in the formation. Minimum over-displacement may tend toyield a higher-strength consolidated formation while a consolidatingtreatment fluid that is over-displaced more completely into theformation will yield lower strength in the near well bore area.

The term “resin” as used herein refers to any of numerous physicallysimilar polymerized synthetics or chemically modified natural resinsincluding thermoplastic materials and thermosetting materials. Resinssuitable for use in the present invention include two-component epoxyresins, furan-based resins, phenolic-based resins, and phenol/phenolformaldehyde/furfuryl alcohol resins. U.S. Pat. No. 7,690,431, therelevant disclosure of which is hereby incorporated by reference,describes these resins and their use in consolidating formationparticulates.

In some embodiments in which a resin is used in a resin treatment fluid,the resin may be present in the resin treatment fluid in an amount inthe range of about 0.01% to about 50% by volume of treatment fluid. Insome embodiments, the resin may be introduced to the injection well inan amount ranging from a lower limit of about 0.01%, 0.02%, 0.05%, 0.1%,0.5%, 1%, 2%, 3%, 4%, 5%, or 6% by volume of the resin treatment fluid,to an upper limit of about 50%, 45%, 40%, 35%, 30%, 25%, 20%, 17% 15%,12%, 10%, 7%, 5%, or 3% by volume of the resin treatment fluid, andwherein the percentage of resin may range from any lower limit to anyupper limit to the extent that the selected range encompass a subsetbetween the upper and lower limits. Some of the lower limits listedabove are greater than some of the listed upper limits, one skilled inthe art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit. Inother embodiments, the amount of resin used is based on the intervalbeing treated. For example, the resin may be introduced to an injectionwell so that a total of from about 0.01 gallons to about 100 gallons ofresin per foot of interval being treated is used. In some embodiments,the resin may be introduced to the injection well in an amount rangingfrom a lower limit of about 0.01 gal, 0.02 gal, 0.05 gal, 0.1 gal, 0.5gal, 1 gal, 2 gal, 3 gal, 4 gal, 5 gal, or 6 gal per foot of intervalbeing treated, to an upper limit of about 100 gal, 90 gal, 80 gal, 70gal, 60 gal, 50 gal, 40 gal, 30 gal, 20 gal, 10 gal, 5 gal, 4 gal, or 2gal per foot of interval being treated, and wherein the amount of resinmay range from any lower limit to any upper limit to the extent that theselected range encompass a subset between the upper and lower limits.Some of the lower limits listed above are greater than some of thelisted upper limits, one skilled in the art will recognize that theselected subset will require the selection of an upper limit in excessof the selected lower limit.

Sand Control Devices

The sand control devices are essentially filter assemblies used toretain either formation solids or particulates such as gravel that areplaced into the subterranean formation. Suitable sand control devicesthat may be used in the present invention include sand control screens,liners, and combinations thereof. A sand control liner is generally awell bore tubular in which slots (slotted liner) or holes (perforatedliner) have been made before the tubular is placed into the well bore. Asand control screen is generally a more flexible filter assembly thatmay be used in conjunction with a liner or alone. As will be understoodby one of ordinary skill in the art, a wide range of sizes and screenconfigurations are available to suit the characteristics (such as size,spherocity, etc.) of the formation solids or particulates that are meantto be controlled by the device. The sand control device, with or withoutadded gravel, presents a barrier to migrating sand from the formationwhile still permitting fluid flow.

Any sand control screen or perforated liner known in the art andsuitable for the injection well being treated may be used in theembodiments of the present invention. One known type of sand controlscreen commonly used in open hole completions where gravel packing maynot be feasible, is expandable sand control screens. Typically,expandable sand control screens are designed to not only filterparticulate materials out of the formation fluids, but also provideradial support to the formation to prevent the formation from collapsinginto the well bore. Another open hole completion screen type known inthe art is a stand alone screen. Typically, stand alone screens may beused when the formation generally comprises a more uniform particle sizedistribution. Still another known type of sand control screen is atelescoping screen whereby hydraulic pressure is used to extend thetelescoping screen radially outwardly toward the well bore. This processrequires providing fluid pressure through the entire work string thatacts on the telescoping members to shift the members from a partiallyextended position to a radially extended position. Another type ofsuitable sand control screen is described in United States PatentPublication No. 2009/0173497, the entire disclosure of which is herebyincorporated by reference, and includes a base pipe having at least oneopening in a sidewall portion thereof; a swellable material layerdisposed exteriorly of the base pipe and having at least one openingcorresponding to the at least one opening of the base pipe; atelescoping perforation operably associated with the at least oneopening of the base pipe and at least partially disposed within the atleast one opening of the swellable material layer; and a filter mediumdisposed within the telescoping perforation. Another suitable sandcontrol device is described in U.S. Patent Publication No. 2009/0173490,the entire disclosure of which is hereby incorporated by reference,which describes a swellable packer activated screen approach that mayprovide stand off from the formation to allow filter-cake clean up

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

EXAMPLES Example 1

To provide a control experiment, a test cell was filled with differentlayers of material. From top to bottom, the test cell contained a topplunger, a 40-mesh screen, a layer of 16/20-mesh Carbolite proppant, amixture of smaller than 200-mesh Brazos River sand and 20/40-mesh Bradysand, a layer of 40/60-mesh sand, an 80-mesh screen, and a bottomplunger. Using a peristaltic pump, 100 cm³ of 3% KCl brine was injectedfrom the top of the test cell at 8 cm³ per minute in order to saturatethe sand pack. Then, 3% KCl was flowed through the test cell in thereverse direction (from the bottom of the test cell up through the sandpack) at incremental flow rates of 50, 100, 150, 200 and 300 cm³ perminute. Each flow rate was continued until about 100 cm³ of effluent wasable to be collected in a separate glass bottle. The collected effluentswere visibly cloudy with particulates.

Example 2

A dry test cell was prepared as described in Example 1. Using aperistaltic pump, 100 cm³ of 3% KCl brine was injected from the top ofthe test cell at 8 cm³ per minute in order to saturate the sand pack.Then 100 cm³ of a dilute solution of water-based tackifying emulsion wasflowed through the test cell at 8 cm³ per minute. The dilute solution ofwater-based tackifying emulsion was prepared by diluting 5 cm³ of 20%v/v of 5 cm³ of an aqueous tackifier in 20 cm³ of tap water with 95 cm³of KCl brine. The dilute solution of water-based tackifying emulsion wasfollowed by a post flush of 150 cm³ of KCl brine. Immediately thereafter(no shut-in period), 3% KCl was flowed through the test cell in thereverse direction (from the bottom of the test cell up through the sandpack) at incremental flow rates of 50, 100, 150, 200 and 300 cm³ perminute. Each flow rate was continued until about 100 cm³ of effluent wasable to be collected in a separate glass bottle. The effluents collectedin this example were visibly clearer (contained fewer particulates) thanthe effluents collected in Example 1.

Example 3

A dry test cell was prepared as described in the preceding examples.Using a peristaltic pump, 100 cm³ of 3% KCl brine was injected from thetop of the test cell at 8 cm³ per minute in order to saturate the sandpack. Then 100 cm3 of a low-concentration, water-based epoxy resinemulsion was flowed through the test cell at 8 cm³ per minute. The lowconcentration, water-based epoxy resin emulsion was prepared by diluting10 cm³ of a disperse water-borne, two-part epoxy resin system, 5 cm³ ofa water-based epoxy resin emulsion and 5 cm³ of water-based epoxy resinemulsion with 90 cm³ of 3% KCl brine. The test cell was shut in at 150°F. for 20 hours. Then 3% KCl was flowed through the test cell in thereverse direction (from the bottom of the test cell up through the sandpack) at incremental flow rates of 50, 100, 150, 200 and 300 cm³ perminute. Each flow rate was continued until about 100 cm³ of effluent wasable to be collected in a separate glass bottle. The effluents collectedin this example were more visibly clearer (contained fewer particulates)than the effluents collected in Example 1.

Example 4

In a dry test cell, about 180 grams of 70/170-mesh sand was packed in atest cell. This sand pack was placed between 0.5-inch layers of40/60-mesh sand. Wire-mesh screens were placed at the bottom and top ofthe 40/60-mesh sand layers to hold the sand pack in place. Cold tapwater was connected to the test cell and allowed to flow through thesand pack for 4 hours at 15 to 30 cm³ per minute. After this initialflowing period, the flow of tap water was temporarily suspended. Avolume of 100 cm³ of water containing 0.5 cm³ of a cationic surfactantwas injected into the sand pack at 25 cm³ per minute. After thisinjection, a volume of 50 cm³ of water-borne, two-part epoxy resinsystem (FDP-S863-07, Halliburton Energy Services, Duncan, Okla.)containing 0.5 cm³ of a water-based epoxy resin emulsion and 0.5 cm³ ofa water dispersible curing agent was injected into the sand pack at 25cm³ per minute. The flow of tap water was then re-established at 15 to30 cm³ per minute until the next day. This process was repeated for 6days. The sand pack and test cell remained at room temperature. On theseventh day, the sand pack was removed from the test cell. The sand packwas consolidated. The consolidated core was cut into smaller segmentsfor Brazilian tensile strength measurements. The tensile strengths oftop, middle, and bottom segments were 19 psi, 32 psi, and 41 psi,respectively.

Example 5

In a dry test cell, about 180 grams of 70/170-mesh sand was packed in atest cell. This sand pack was placed between 0.5-inch layers of40/60-mesh sand. Wire-mesh screens were placed at the bottom and top ofthe 40/60-mesh sand layers to hold the sand pack in place. Cold tapwater was connected to the test cell and allowed to flow through thesand pack for 4 hours at 15 to 30 cm³ per minute. After this initialflowing period, the flow of tap water was temporarily suspended. Avolume of 100 cm³ of water containing 0.5 cm³ of a cationic surfactantwas injected into the sand pack at 25 cm³ per minute. After thisinjection, a volume of 50 cm³ mixture containing 25 cm³ of water-borneepoxy resin (i.e., component A of FDP-S863-07, Halliburton EnergyServices, Duncan, Okla.) and 25 cm³ of 20% v/v of 5 cm³ of an aqueoustackifier (FDP-S965-10, Halliburton Energy Services, Duncan, Okla.) in20 cm³ of tap water was injected into the sand pack at 25 cm³ perminute. The flow of tap water was then re-established at 15 to 30 cm³per minute until the next day. This process was repeated for 6 days. Thesand pack and test cell remained at room temperature. On the seventhday, the sand pack was removed from the test cell. The sand pack wasconsolidated. The consolidated core was cut into smaller segments forBrazilian tensile strength measurements. The tensile strengths of top,middle, and bottom segments were 6 psi, 6 psi, and 6 psi, respectively.

Example 6

In a dry test cell, about 180 grams of 70/170-mesh sand was packed in atest cell. This sand pack was placed between 0.5-inch layers of40/60-mesh sand. Wire-mesh screens were placed at the bottom and top ofthe 40/60-mesh sand layers to hold the sand pack in place. Cold tapwater was connected to the test cell and allowed to flow through thesand pack for 4 hours at 15 to 30 cm³ per minute. After this initialflowing period, the flow of tap water was temporarily suspended. Avolume of 100 cm³ of water containing 0.5 cm³ of a cationic surfactantwas injected into the sand pack at 25 cm³ per minute. After thisinjection, a volume of 50 cm³ of an aqueous mixture containing 10 cm³ offurfuryl alcohol monomer was injected into the sand pack at 25 cm³ perminute. After this injection, a post-flush volume of 50 cm³ of 10%hydrochloric acid solution was injected into the sand pack at 25 cm³ perminute. The flow of tap water was then re-established at 15 to 30 cm³per minute until the next day. This process was repeated for 6 days. Thesand pack and test cell remained at room temperature. On the seventhday, the sand pack was removed from the test cell. The sand pack wasconsolidated. The consolidated core was cut into smaller segments for

Brazilian tensile strength measurements. The tensile strengths of top,middle, and bottom segments were 14 psi, 21 psi, and 1 psi,respectively.

The results obtained in Examples 4-6 indicated the injection ofaggregating or consolidating agents as part of the water injectionprovides cohesion or consolidation for the unconsolidated formation sandin the water-injection wells to prevent formation sand from producingback.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” froman upper limit to a lower limit, or, equivalently, “from approximatelya-b”) disclosed herein is to be understood to set forth every number andrange encompassed within the broader range of values. Also, the terms inthe claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee. Moreover, the indefinitearticles “a” or “an,” as used in the claims, are defined herein to meanone or more than one of the element that it introduces. If there is anyconflict in the usages of a word or term in this specification and oneor more patent or other documents that may be incorporated herein byreference, the definitions that are consistent with this specificationshould be adopted.

What is claimed is:
 1. A method comprising: providing an injection wellwherein the injection well includes unconsolidated particulates in oneor more formation intervals along the wellbore that accept injectionfluid; providing a consolidating treatment fluid comprising a base fluidand a consolidating agent; introducing a consolidating treatment fluidthrough the injection well, while the well is under injection, such thatthe consolidating treatment fluid enters into a portion of a formationinterval along the wellbore that accepts injection fluid; and, allowingthe consolidating fluid to consolidate formation particulates therein.2. The method of claim 1 wherein the consolidation fluid is selectedfrom the group consisting of a tackifying agent, a resin, and acombination thereof.
 3. The method of claim 1 wherein the consolidationfluid is a tackifying agent selected from the group consisting of anaqueous tackifying agent, a non-aqueous tackifying agent, a gelablecomposition, and a zeta potential altering system, and a combinationthereof.
 4. The method of claim 1 wherein the consolidation fluid isprovided in a form selected from the group consisting of a dilutedispersion in an aqueous base fluid, a micro-emulsion in an aqueous basefluid, or a micro-dispersion of the chosen agent in an aqueous basefluid.
 5. The method of claim 1 wherein the consolidating agent ispresent in the base fluid in an amount ranging from 0.01% to about 20%.6. A method comprising: providing an injection well; providing aconsolidating treatment fluid comprising a base fluid and aconsolidating agent; introducing the consolidating treatment fluidthrough the injection well and into a portion of a subterraneanformation surrounding the injection well at a first flow rate; then,introducing the consolidating treatment fluid through the injection welland into a portion of a subterranean formation surrounding the injectionwell at a second flow rate; then, introducing the consolidatingtreatment fluid through the injection well and into a portion of asubterranean formation surrounding the injection well at a third flowrate; wherein the volume percent of consolidating agent in theconsolidating treatment fluid may vary between the first flow rate, thesecond flow rate, and the third flow rate; and, wherein the first flowrate, second flow rate, and third flow rate are each different.
 7. Themethod of claim 6 wherein the flow rate increases from first flow rateto second flow rate to third flow rate and wherein the first flow rate,second flow rate, third flow rate are all below the matrix flow rate. 8.The method of claim 6 wherein the flow rate decreases from first flowrate to second flow rate to third flow rate and wherein the first flowrate, second flow rate, third flow rate are all below the matrix flowrate.
 9. The method of claim 6 wherein the consolidation fluid isselected from the group consisting of a tackifying agent, a resin, and acombination thereof.
 10. The method of claim 6 wherein the consolidationfluid is a tackifying agent selected from the group consisting of anaqueous tackifying agent, a non-aqueous tackifying agent, a gelablecomposition, and a zeta potential altering system, and a combinationthereof.
 11. The method of claim 6 wherein the consolidation fluid isprovided in a form selected from the group consisting of a dilutedispersion in an aqueous base fluid, a micro-emulsion in an aqueous basefluid, or a micro-dispersion of the chosen agent in an aqueous basefluid.
 12. The method of claim 6 wherein the volume percent ofconsolidating agent decreases from first flow rate to second flow rateto third flow rate.
 13. The method of claim 6 wherein the volume percentof consolidating agent increases from first flow rate to second flowrate to third flow rate.
 14. The method of claim 6 wherein: the volumepercent of consolidating agent at the first flow rate is between about2% to about 10%; the volume percent of consolidating agent at the firstflow rate is between about 1% to about 5%; and, the volume percent ofconsolidating agent at the first flow rate is between about 0.1% toabout 2.5%.
 15. A method comprising: providing an injection well;introducing a first consolidating treatment fluid through the injectionwell and into a portion of a subterranean formation surrounding theinjection well wherein the first consolidating treatment fluid comprisesa base fluid and a first volume percent of consolidating agent; then,introducing a second consolidating treatment fluid through the injectionwell and into a portion of a subterranean formation surrounding theinjection well wherein the second consolidating treatment fluidcomprises a base fluid and a second volume percent of consolidatingagent; then, introducing a third consolidating treatment fluid throughthe injection well and into a portion of a subterranean formationsurrounding the injection well wherein the third consolidating treatmentfluid comprises a base fluid and a third volume percent of consolidatingagent; wherein the first volume percent of consolidating agent, secondvolume percent of consolidating agent, and third volume percent ofconsolidating agent are each different.
 16. The method of claim 15wherein the volume percent of consolidating agent increases from firstvolume percent of consolidating agent to second volume percent ofconsolidating agent to third volume percent of consolidating agent. 17.The method of claim 15 wherein the volume percent of consolidating agentdecreases from first volume percent of consolidating agent to secondvolume percent of consolidating agent to third volume percent ofconsolidating agent.
 18. The method of claim 15 wherein theconsolidation fluid is selected from the group consisting of atackifying agent, a resin, and a combination thereof.
 19. The method ofclaim 15 wherein the consolidation fluid is a tackifying agent selectedfrom the group consisting of an aqueous tackifying agent, a non-aqueoustackifying agent, a gelable composition, and a zeta potential alteringsystem, and a combination thereof.
 20. The method of claim 15 wherein:the first volume percent of consolidating agent that is between about 2%to about 10%; the second volume percent of consolidating agent isbetween about 1% to about 5%; and, the third volume percent ofconsolidating agent is between about 0.1% to about 2.5%.